Petroleum reservoirs, aquifers, and other geological features may be highly heterogeneous in composition and may generally include preferential flow paths resulting from natural fracture networks formed therein. Simulating the flow of fluid in these features can provide valuable information, for example, to well operators, drilling service provides, etc.
A reservoir or aquifer can be represented by a grid of blocks of porous media and a network of fractures. Dual-porosity and dual-permeability, single-porosity, and discrete fracture models are approaches used in reservoir simulation to model these media, and these approaches have been accepted as suitable for a variety of purposes. In discrete fracture models, for example, the fractures may be represented in n−1 dimensions, with the model being represented overall in n-dimensions. This simplification may provide a beneficial tradeoff between accuracy and efficiency, i.e., conservation of computing resources, as the aperture (flowpath area) of the fractures may be generally small relative to each block of the model. Accordingly, in a three-dimensional block model, the fractures may be each represented as two-dimensional facets, while two-dimensional models may represent fractures as edges. Furthermore, in such two-dimensional models, the edges representing the fractures may be characterized by center coordinates, orientation, hydraulic permeability, and aperture distribution.
Various numerical methods based on discrete fracture models have been used to simulate single and multiphase flow in such modeled fractured media. For example, the finite-volume (FV) method is a mass conservative method that gives correct location of fronts or boundaries between blocks. In this type of method, however, the grid blocks at the fracture intersections may be “removed,” that is, the boundaries between fracture grid blocks and the intersection block are neglected and the area of the intersection block, which is small compared to the surrounding blocks, is subsumed into the adjacent blocks. This simplification is used to avoid a need for time steps that are small enough to observe meaningful characteristics at the relatively small intersection block, because such time steps are generally excessively and/or impracticably small for analyzing the larger, surrounding grid blocks.
Thus, instead of actually modeling the behavior of the fluid in the fractured media at the intersection, the behavior of the flow is approximated, typically using the Y-A or “star-delta” approximation. However, this approximation is derived from analyses of electrical current flow. While this approximation may be accurate for single-phase incompressible flow situations, it may be unsuitable for complexities that arise in a two-phase flow, compressible flow, etc. situations, which may be common in real-world applications
What is needed, then, is an efficient system and method for modeling fracture network flow properties that accurately accounts for two-phase flow.